pngne 2020-2021 revenue requirements xhibit e a-6 · suite 410, 900 howe street vancouver, bc...

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File 62353 | Information Request No. 2 1 of 1

May 15, 2020 Sent via email/eFile

PNGNE 2020-2021 REVENUE REQUIREMENTS EXHIBIT A-6

Mr. Verlon Otto Director, Regulatory Affairs Pacific Northern Gas (NE) Ltd. 750 – 888 Dunsmuir Street Vancouver, BC V6C 3K4 [email protected] Re: Pacific Northern Gas (NE) Ltd. – Fort St. John/Dawson Creek and Tumbler Ridge Divisions –

2020-2021 Revenue Requirements Application – Project Number 1599058 – Information Request No. 2 Dear Mr. Otto: Further to your 2020–2021 Revenue Requirements Application dated November 29, 2019, enclosed please find British Columbia Utilities Commission Information Request (IR) No. 2 for the Fort St. John/Dawson Creek and Tumbler Ridge Divisions, which includes all public BCUC IRs for this second round. In accordance with Order G-96-20 setting out the regulatory timetable for this proceeding, please file your responses on or before Wednesday, June 3, 2020. Sincerely, Original signed by: Patrick Wruck Commission Secretary /dg Enclosure

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PNG (NE) – 2020-2021 RRA BCUC IR No. 2 1 of 28

Pacific Northern Gas (N.E.) Ltd. – Fort St. John / Dawson Creek Division and Tumbler Ridge Division 2020-2021 Revenue Requirements Application

INFORMATION REQUEST NO. 2 TO PACIFIC NORTHERN GAS (N.E.) LTD.

Table of Contents Page no. A. General ..........................................................................................................................................................1

B. Demand Forecast, Revenue and Margin .......................................................................................................2

C. Cost of Gas .....................................................................................................................................................3

D. Operating Expenses .......................................................................................................................................4

E. Maintenance Expenses ............................................................................................................................... 10

F. Administrative & General Expenses ........................................................................................................... 11

G. Deferral Accounts ....................................................................................................................................... 12

H. Shared Services Recovery from PNG(NE) ................................................................................................... 13

I. Rate Base .................................................................................................................................................... 17

J. Capital Structure and Return on Capital..................................................................................................... 22

K. Capital Expenditure Reporting – Actual vs Decision .................................................................................. 23

L. Cost of Service Reporting – Actual vs Decision .......................................................................................... 24

M. Other Matter to Be Addressed from Prior Year Decisions ......................................................................... 25

A. GENERAL

REFERENCE: GENERAL Exhibit B-5, British Columbia Old Age Pensioners’ Organization et al. (BCOAPO) IR Series 1.0 COIVD-19 Pandemic

In its responses to BCOAPO information request (IR) series 1.0, Pacific Northern Gas (N.E.) Ltd. (PNG(NE)) provided information regarding the impact of the COVID-19 pandemic on PNG(NE)’s forecast cost of service and operations. PNG(NE) also noted that “… the BCUC approved PNG(NE)’s request, on an interim basis, for the creation of a COVID-19 deferral account to capture unrecovered revenues and unplanned costs arising from the COVID-19 pandemic.”

Please provide an update on the impact to-date and the expected future impact of the COVID-19 pandemic on PNG(NE) and its operations.

65.1.1 Please provide an update to address whether the COVID-19 pandemic is expected to have an impact on the timing of capital and IT projects, the timing of new staff position start dates and/or forecast costs during the test period.


65.1.2 Please provide an update on the expected impact of the COVID-19 pandemic on forecast demand for all customer classes during the test period.

Please confirm, or otherwise explain, that the COVID-19 deferral account will capture incremental costs associated with ongoing operations that are the direct result of the COVID-19 pandemic but it will not record any reductions in forecast costs that result from the COVID-19 pandemic.

Considering the responses provided above, please identify and discuss amendments (if any) to the Application that are necessary due to the impacts of the COVID-19 pandemic.

B. DEMAND FORECAST, REVENUE AND MARGIN

Reference: DEMAND FORECAST, REVENUE AND MARGIN Exhibit B-2 (Amended Application), Fort St. John/Dawson Creek (FSJ/DC) Division Section 2.1, pp. 25-26, Exhibit B-3, IR Series 4.0 Other Customer Classes

In response to BCUC IR 4.3 in Exhibit B-3, PNG(NE) stated:

PNG(NE) submits that Table 11 in the Amended Application should reflect the test year deliveries for this customer based on their contractual demand of 980,000 GJ rather than forecast physical deliveries of 600,000 GJ to alleviate any confusion as the margin shown in Table 11 is also based on their contractual demand.

Please provide the updated and correct Table 11 as highlighted in the preamble above.

On page 26 of the FSJ/DC Amended Application PNG submits: “The bulk of this decrease is attributable to fuel gas deliveries to a liquefied natural gas (LNG) plant in Dawson Creek being less than the contracted demand of 980,000 GJ per year. There is no margin effect as this customer is provided service under a minimum take-or-pay contract.” In its response to BCUC IR 4.2 in Exhibit B-3, PNG submitted that “[t]he customer operating the LNG facility in Dawson Creek is Campus Energy Partners LP. The two gas productions facilities in Fort St. John that declared bankruptcy were owned by Ranch Energy Corporation and had transportation service agreements with PNG(NE).”

Please describe any credit requirements in the agreement between PNG(NE) and Campus

Energy Partners LP and the current status of these requirements.

Please discuss if there are any termination clauses in the TSA between PNG(NE) and Ranch Energy Corporation that provide for any amounts owing to PNG(NE) as a result of the contract termination due to bankruptcy. If yes, please provide the amounts owing to PNG(NE) and any efforts to recover these amounts to date.


C. COST OF GAS

Reference: COST OF GAS Exhibit B-2 FSJ/DC, Section 2.2, p. 28; Tumbler Ridge (TR), Section 2.2, p. 27; PNG-West Division 2020-2021 RRA proceeding, Exhibit B-2, Section 2.2.3, pp. 30, 32, Exhibit B-3, IR 5.0 series Unaccounted for Gas

In response to BCUC IR 5.1 in Exhibit B-3, PNG(NE) provided the following tables:

Please discuss whether PNG(NE) has identified why there are mostly unaccounted for gas (UAF) gains in the TR division as compared to PNG(West) and PNG(NE) FSJ/DC division. If yes, please provide details of the same.


The UAF component in the Company Use gas cost refers to the budgeted percentage of UAF embedded in the calculation of Company Use gas expense for each of the PNG-West, FSJ/DC and TR Divisions. The UAF component in the Company Use gas cost is set at 1% for FSJ/DC and 0% for TR. For PNG-West, this had been set at 0% in prior years, however, in the 2020-2021 RRA, PNG-West is seeking BCUC approval to set the UAF component in the Company Use gas cost at 1%.

The UAF loss cap is the maximum UAF loss percentage that can be recorded in the UAF deferral account without seeking further approval from the BCUC. The UAF loss cap is set at 1.5% for FSJ/DC and 1.0% for TR. For PNG-West, the UAF loss cap had been set at 1.0% in prior years; however, as noted previously, PNG-West is seeking approval to set the UAF loss cap at 1.5% in the 2020-2021 RRA.

Please explain why there are differences in the budgeted percentage of UAF embedded in the calculation of Company Use gas expense and UAF loss caps for each of the PNG-West, FSJ/DC and TR Divisions on the PNG system.


D. OPERATING EXPENSES

Reference: OPERATING EXPENSES Exhibit B-3, BCUC IR 6.1, 6.2 System Integrity Focus


As the age of PNG(NE)’s infrastructure increases, there is an increasing likelihood of investigative digs and cutouts resulting from inspection works, such as DCVG surveys. As work is executed, more information on the condition of the system is gathered, often resulting in a compounding effect of additional scope. …

PNG(NE) has an increased focus on other regular interval maintenance activities, such as pipeline inspections (air surveys), aerial crossing, watercourse crossing and documentation of change surveys, right of way vegetation management and signage.

Please discuss whether PNG(NE) is increasing the number of direct current voltage gradient (DCVG) surveys completed each year. If so, please elaborate on whether this increased frequency is as a result of compliance with PNG’s Integrity Management Plans, a result of compliance with related codes, standards and regulations or a result of other factors.

Please clarify the meaning of “increased focus” on other maintenance activities. Please discuss whether increased focus results in conducting the listed activities more frequently, conducting some of the listed activities for the first time, expanding the use of the listed activities to new segments of PNG(NE)’s system or some other meaning.


These noted changes have resulted in direct and appreciable focus and mandated requirements by the BCOGC pertaining to pipeline segment by segment risk management and the implementation of a new assessment and audit program directed at pipeline and facility assets 50 years of age or older, thereby encompassing many of PNG(NE)’s transmission and distribution system assets. …

…

Given all of this, PNG(NE)’s overall understanding and appreciation for integrity management-based requirements continues to mature and broaden and with this comes changes to operational practice and associated expense to ensure compliance and continued responsible operation as it pertains to pipeline safety and reliability…

The BCOGC has also drawn focus to “aged pipelines” and recognized the elevated risk by undertaking specific assessments on aging pipelines in BC.

Please provide any directives, letters or documents from the BC Oil and Gas Commission (BCOGC) referencing the aged pipeline assessment and audit program.

Please provide an estimate of the costs included within this Test Period associated with responding to BCOGC mandated requirements, including costs associated with responding to requirements of a pipeline segment-by-segment risk assessment and aged pipeline assessment, as well as other BCOGC mandated requirements.


Reference: OPERATING EXPENSES Exhibit B-2 TR, Section 2.3.2, p. 29; Exhibit B-3, BCUC IR 13.3; Exhibit B-4 BCUC IR 2.4; PNG-West Division, 2016-2017 RRA proceeding, Order G-131-16 with reasons for decision dated August 10, 2016, Section 4.1, p. 18 Accounting Treatment of ILI and Investigative Dig Costs


PNG(NE) submits it is aligned with response from industry to have previously ‘unpiggable’ pipelines become ‘piggable’, as previously outlined in the Amended Application. The ability to run ILI tools creates opportunity to more completely align and comply with the CSA Z662 standard and the related intent of the PNG(NE) Integrity Management Plan. As improved technology becomes available for integrity management, PNG(NE) believes it has a responsibility to assess and implement it, if it is practicable to do so.


There are no in line inspection (ILI) related activities in scope for Tumbler Ridge and no costs have been included in BCUC Account 665 for Test Years 2020 and 2021 as the pipelines are not currently inspectable by ILI. PNG(NE) has planned investigative digs for the purposes of ECDA and their costs are included under BCUC Account 655 for Test Years 2020 and 2021. PNG(NE) notes that the accounting treatment for all the activities and costs related to ILI tool runs and investigative digs have been addressed in prior revenue requirements application decisions as follows:

• ILI runs are normally expensed in the year incurred in accordance with US GAAP. Close interval surveys (CIS) are similar to ILI runs except that they are above ground and will typically result in investigative digs, therefore, they would follow a similar accounting treatment.

• Investigative Digs - this was specifically addressed in the decision on the PNG(NE) 2013 Revenue Requirements Application under BCUC Order G-131-13 where PNG(NE) was directed to record its forecast for investigative digs in its cost of service starting in 2013 and create a new deferral account to capture any variances to be amortized the following year.

On pages 29 and 30 of the TR Amended Application, PNG(NE) states:

The costs in this account cover the routine operating costs of the pipelines that PNG(NE) operates. Typical activities include: inspecting and operating above ground structures, as well as other facilities for safety and reliability; performing in-line inspections and close interval surveys and follow-up investigative digs; operating and monitoring the Supervisory Control and Data Acquisition (SCADA) system; maintenance of vegetation on the rights of way (ROW) and operation of the cathodic protection system. [Emphasis added]

In addition, PNG(NE) will further reinforce its integrity management plan by working toward upgrading the TR Division transmission line to be compatible with new in-line inspection tooling that is available to the industry.


Please clarify which PNG(NE) pipeline system segments are currently inspectable by ILI. Please distinguish which segments are capable of performing in-line cleaning and which segments are capable of performing in-line inspection.

Please explain whether PNG(NE) completes or is expected to complete any EMAT ILI or ILI runs on the FSJ/DC system during the 2020/2021 Test Period.

69.2.1 If yes, please provide the cost breakdown by year and discuss if PNG(NE) accounts for EMAT ILI and other ILI runs for regulatory purposes in the same manner as PNG-West. Please comment on any differences.

On page 18 in Order G-131-16, the BCUC states that “[i]n the Panel’s view, it is more appropriate to use regulatory accounts in circumstances where financial accounting principles do not allow for capitalization of costs and where the recording of such costs as operational expenses would result in large and volatile rate impacts.”

Please clarify whether US GAAP allows for either capitalizing or expensing investigative digs costs, with reference to the applicable US GAAP section.

69.3.1 Please identify the relevant factors from PNG(NE)’s perspective that should be considered in determining the accounting treatment for investigative dig costs in accordance with US GAAP.

Reference: OPERATING EXPENSES Exhibit B-4, BCUC IR 2.1 Account 665 - Pipelines


PNG(NE) further notes that while the 2020 forecasted costs have been reduced due to more favorable contractor pricing for survey work, the 2021 forecast provided in the Amended Application remains consistent with current expectations for the cost of ECDA and necessary resulting repairs. PNG(NE) will reflect a $35,000 reduction to contractor costs for Test Year 2020 in the final regulatory schedules.

Please discuss the rate impact of the $35,000 reduction in contractor cots referenced in the preamble for each year of the Test Period.

Reference: OPERATING EXPENSES Exhibit B-3, BCUC IR 7.1, 7.4 Operation Field Staff Positions – New


The costs associated with the two new utility person full-time equivalent positions are allocated to the various operating and maintenance expense and capital expenditure accounts where the labour activities are being performed, similar to other bargaining unit positions. PNG(NE) notes that bargaining unit employees complete time sheets to track the type and the location of activities they are working on. The labor costs are allocated according to specifically identifiable projects as per the time sheet details.


In terms of cost savings, by reducing reliance on temporary employees, PNG(NE) will save $115,000 (between O&M and capital). PNG(NE) notes that the cost for the two FTE


bargaining unit positions is approximately $194,000, and while on a net basis there are not significant savings as this change results in a reallocation of costs from contractors to employee labour, there are additional qualitative benefits…

Please provide a breakdown of the forecast costs and cost savings associated with the two new positions by account (O&M and Capital) for Test Year 2020 and 2021. Please include the following cost categories in the breakdown of cost savings; (i) temporary employees, (ii) summer students, and (iii) contractors.

Reference: OPERATING EXPENSES Exhibit B-2 FSJ/DC, Section 2.6, p. 51; Exhibit B-3, BCUC IR 10.1, 10.2, 10.2.1.1, 10.5 Account 711/713/714 – New CIS System


The new CIS system costs are composed of the following:

1. BCUC 713 - Shared Services Allocation for Implementation Costs – as noted in the Amended Application and the preamble above, the total shared implementation costs of $16.5 million will be capitalized by AUI and amortized over ten years and the related costs will be allocated to PNG on a cost recovery basis using customer count. For Test Year 2021, the total costs to AUI, HGL and PNG will be $1.74 million of which PNG will be allocated $0.51 million. PST will be required to be added to these shared services charges to PNG which will result in a total of $0.55 million and will be allocated to PNG-West and the PNG(NE) divisions based on customer count as noted in the table below:

2. BCUC 713 - Shared Allocation of CIS Support Costs – these include costs required to support the new CIS system and include the costs to operate the HelpDesk and other IT related costs. The total costs for Test Year 2021 are forecast to be $1.4 million of which PNG will be allocated $0.26 million based on customer count. PST will also be required to be added to this amount and result in total costs of $0.28 million to be allocated to PNG-West and the PNG(NE) divisions as follows:

3. BCUC 713 - Direct Operating Costs – this refers to the annual license maintenance fees to be paid by PNG forecast to be $20,415 for Test Year 2021 to be allocated to all the PNG divisions based on customer count and result in an allocation of $9,985 to PNG-West, $9,834 to PNG(NE) FSJ/DC and $596 to PNG(NE) TR division.


Further, on page 51 of the PNG(NE) FSJ/DC Amended Application, PNG(NE) states that there is an “[i]ncreased cost allocation of approximately $195,000” in Test Year 2021 over Test Year 2020, regarding Account 713 – Vancouver Vertex Billing Services.

Considering costs will be allocated to PNG(NE) divisions based on customer count, please explain whether and how often the allocation methodology will be updated based on changes in customer count.

Please reconcile the 2021 forecast operating costs allocated to FSJ/DC in response to BCUC IR 10.1, as outlined in red above, to the increased cost allocation in Account 713 of approximately $195,000 in Test Year 2021. As part of the reconciliation, please delineate the expected cost increases.


…PNG Consolidated expects to realize savings of approximately $100,000 on an annual basis and has reflected the proportionate savings in Test Year 2021.

PNG Consolidated also expects to realize further financial benefits from the new CIS system commencing in Year 2022 after the new CIS system has been fully implemented. PNG Consolidated expects that less internal resources will be required with the new system and plans to reduce the CIS technical support group by one headcount. PNG Consolidated is also assessing redeploying the Customer Care resource to other work. The CIS technical support group headcount will coincide with the anticipated employee retirement. [Emphasis Added]

In response to BCUC IR 10.2.1.1 in Exhibit B-3, PNG(NE) stated:

PNG(NE) notes that there are no estimated cost savings from the CIS solution reflected in the financial schedules… PNG(NE) determined that the joint CIS project with its sister utilities was the best path forward in view of current circumstances and the need to for a new CIS solution. This enables PNG(NE) to achieve lower implementation costs and will also result in further financial benefits commencing in Year 2022 from lower resources required n the CIS technical support group and redeployment of customer care resources. [Emphasis Added]

Please provide a breakdown of the expected cost savings to be realized from the new CIS system by each of the divisions (PNG West, PNG(NE) FSJ/DC and TR) commencing in Year 2022 and onwards.

Please provide the anticipated cost saving for PNG(NE) divisions, if any, as a result of one less CIS support technician.


4. BCUC 487 - Direct Capital Costs – as noted in the Amended Application and the preamble, PNG will incur direct capital costs for SAP licenses and data extraction from Banner to VertexOne to be allocated to PNG-West and the PNG(NE) divisions as follows:



PNG(NE) confirms that the data extraction costs totalling approximately $12,000 have been allocated to the TR division and are capitalized. These costs are reflected as a plant addition under BCUC account 489 in Test Year 2021.

Please confirm, or explain otherwise, that the response to BCUC IR 10.5 should read “these costs are reflected as a plant addition under BCUC account 487” rather than “489”.

72.5.1 If confirmed, please reconcile the amount allocated to TR of $6,048 in Test Year 2021, in response to IR 10.1, to the approximate $12,000 data extraction costs allocated to the TR division, in response to IR 10.5.

72.5.2 If not confirmed, please provide the methodology for allocating data extraction costs between Account 487 and 489.

Reference: OPERATING EXPENSES Exhibit B-3, BCUC IR 11.2 Account 688 – Other General Operations


The cost for third party welders was $397,621 for 2018 and $188,008 for 2019. A large part of the reliance on third parties relates to unanticipated events, such as leaks and emergencies, which are difficult to forecast into a cost savings. However, PNG(NE) notes that with properly trained and qualified personnel, the internal welders will be utilized when possible. An in-service weld performed by a third party can cost between $20,000-$100,000 and is dependent upon the nature of the requirements.

Please clarify whether any reduction in forecast welding costs is reflected in the Test Period as a result of utilizing internal welders rather than third-party welders. If not, please explain why not.

Please quantify the expected savings and provide the expected timing of when these savings will be achieved.

Reference: OPERATING EXPENSES Exhibit B-2 TR, Section 3.2.2.1, p. 85; Exhibit B-4, BCUC IR 3.1; Exhibit B-5, BCOAPO IR 6.1 Other – Including Account 673

In response to BCUC IR 3.1 in Exhibit B-4, PNG(NE) provided the following breakdown of expenditures for “Other – Including Account 673” for Actual and Decision 2019 and Test Year 2020 and 2021:

Please explain the methodology used to forecast the Test Year 2020 and 2021 labour costs of $65,000 and $50,000 respectively.


Please explain why the Test Year 2020 labour forecast is expected to be in line with the Decision 2019 amount of $63,000 rather than Actual 2019 of $14,000.

In relation to Account 673/675/712/718 – Other, on page 85 of the TR Amended Application, PNG(NE) states:

The actual costs for 2019 included in this account are $74,000 or 52.7% lower than those approved under Decision 2019. This is primarily due to lower labour costs incurred during the year as a result of a decline in customer activity due to the downturn in the economy, particularly impacting housing developments in the Tumbler Ridge area.

In response to BCOAPO IR 6.1, PNG(NE) stated:

Within the TR Division, PNG(NE) is forecasting little or no organic growth during the test years, however, PNG(NE) is projecting an increase in the CNRL load in 2020, as compared to 2019, of approximately 70 TJ or 10 percent.

Please confirm whether the expected increase in the CNRL load in 2020 was considered in the development of the labour forecast of $65,000 included in “Other – Including Account 673” for Test Year 2020.

E. MAINTENANCE EXPENSES

Reference: MAINTENANCE EXPENSES Exhibit B-2 FSJ/DC, Section 2.4.4, p. 37; Exhibit B-3, BCUC IR 13.1, 13.1.1, 13.2; Leak Repair Activities


The increase is comprised of greater internal labour and contractor costs, both of which are attributed to an anticipated increase in the quantity of leak instances requiring intervention. The anticipated leaks are primarily the result of leaking dresser fittings and flanges.

Please clarify whether the anticipated increase in the quantity of leak instances requiring intervention is as a result of dresser fittings and flanges leaking at a greater frequency than in previous years. If so, please explain. If not, please discuss other reasons for the anticipated increase in number of leaks.

Further, in response to BCUC IR 13.1 in Exhibit B-3, PNG(NE) stated:

PNG(NE) further notes an anticipated increase in leak prevention activity by way of integrity dig and coating and corrosion repair response via ECDA that follow DCVG or other over-the-line assessments. The leak repair cost table, and cost growth, is a result of recent under ground and above ground leak trends, independent of cost growth associated with investigative digs.

In response to BCUC IR 13.1.1 in Exhibit B-3, PNG(NE) stated:

PNG(NE) submits that there is a necessary distinction between leak repairs (unplanned reactive response to a leak related gas release) and leak prevention provided by integrity digs and subsequent coating and corrosion repairs that result from DCVG surveys.


In response to BCUC IR 13.2 in Exhibit B-3, PNG(NE) stated: “Given that leak repairs result primarily from leaking dresser fittings, flanges, and to a lesser extent, undetected coating failure related corrosion leaks, costs will continue as long as these conditions exist in the PNG(NE) system.” On page 37 of the Amended Application, PNG(NE) states:

The costs in this line include all other accounts not otherwise listed in the table…Test Year 2020 costs of $191,000 are forecast to increase by $73,000 or 61.4% over Decision 2019 costs of $118,000…Test Year 2021 costs of $195,000 are considered comparable to Test Year 2020 and reflect inflationary pressures on underlying costs.

Please clarify whether leak prevention activities, which are planned and involve integrity digs as well as coating and corrosion repair response, are accounted for in the same maintenance expense account as leak repair activity, which are unplanned and primarily result from leaking dresser fittings and flanges. If not, please explain why not, and specify the account.

Please provide a breakdown of the cost forecast for “All Other” maintenance expense line item for both Test Year 2020 and 2021.

F. ADMINISTRATIVE & GENERAL EXPENSES

Reference: ADMINISTRATIVE & GENERAL EXPENSES Exhibit B-2 FSJ/DC, Section 2.5.8, p. 43; Exhibit B-2 TR, Section 2.5.8, p. 41 Exhibit B-3, BCUC IR 15.3, 15.5 Shared Corporate Services Costs – Deferral Account – Amortization

On page 43 of the FSJ/DC Amended Application and page 41 of the TR Amended Application, PNG(NE) states: “PNG(NE) will seek approval for the amortization of this deferral account in future years as PNG(NE) attaches more customer volumes in the system.” In response to BCUC IR 15.3 in Exhibit B-3, PNG(NE) stated:

PNG(NE) is forecasting low or near zero growth in load in the FSJ/DC Division, with residential and small commercial customer additions offset by a continuing decline in use-per-account

Within the TR Division, PNG(NE) is forecasting little or no organic growth during the test years, however, PNG(NE) is projecting an increase in the CNRL load in 2020, as compared to 2019, of approximately 70 TJ or 10 percent

In response to BCUC IR 15.5 in Exhibit B-3, PNG(NE) stated: “…PNG(NE) proposes to commence amortization of the deferral account when the economic circumstances improve and will revisit this matter in the 2022-2023 RRA submission.”

Under a scenario whereby additional customer volumes on the PNG(NE) system do not materialize over the next few years, please discuss PNG(NE)’s proposed treatment of the deferral account.

76.1.1 Specifically, please discuss whether PNG(NE) would propose to amortize the deferral account in the absence of additional customer volumes on the PNG(NE) system. If yes, please discuss the circumstances under which this would be proposed. If not, please discuss why not.


Please explain the pros and cons of establishing a new deferral account without a set amortization start date nor amortization period.

Reference: ADMINISTRATIVE & GENERAL EXPENSES Exhibit B-2 FSJ/DC, Tab 2, pp. 19-20; Exhibit B-2 TR, Tab 2, pp. 14-15; Exhibit B-4, BCUC IR 6.1; PNG-West Division 2013 RRA proceeding, Order G-114-13 with reasons for decision dated August 1, 2013, Section 6.4, pp. 44-45 Shared Corporate Services Costs – Deferral Account – Interest Expense

On pages 19 and 20, Tab 2, of the Amended Application for the FSJ/DC Division, PNG(NE) presents the continuity of deferred charges for the Test Years 2020 and 2021. Line 28 of each page is the Shared Corporate Services Deferral, and it states the interest rate is “STI”. Further on pages 14 and 15, Tab 2, of the Amended Application for the TR Division, PNG(NE) presents the continuity of deferred charges for the Test Years 2020 and 2021. Line 31 on page 14 and line 30 on page 15 is the Management Fee Adjustment deferral account, and it states the interest rate is “STI”. In response to BCUC IR 6.1 in Exhibit B-4, PNG(NE) clarified:

PNG(NE) submits that the description of this [Management Fee Adjustment] deferral account is in error. The description should be “Shared Corporate Service Costs Deferral.”

On pages 44 and 45 of the 2013 PNG-West RRA Decision, it stated:

For deferral accounts for non-capital items which are amortized beyond one year, the appropriate return is the utility’s Weighted Average Cost of Debt (WACD). For deferral accounts for non-capital items which are amortized over a period of one year or less, the appropriate return is the utility’s short term interest cost.

Please confirm, or explain otherwise, that PNG’s short-term interest cost is the rate applied to the Shared Corporate Service Costs Deferral account and provide a justification for the proposed interest rate.

Please discuss the likelihood that the amortization period for the Shared Corporate Service Costs Deferral account will be greater than one year.

G. DEFERRAL ACCOUNTS

Reference: DEFERRAL ACCOUNTS Exhibit B-3, BCUC IR 22.1; Exhibit B-4, BCUC IR 5.1 Plant Gains and Losses

In response to BCUC IR 22.1 in Exhibit B-3, PNG(NE) provided a list of the assets that were disposed of or retired in 2018 and 2019 for the Fort St John’s and Dawson City Division that resulted in additions to the Plan Gains and Losses – deferral account. And in response to BCUC IR 5.1 in Exhibit B-4, PNG(NE) provided a list of the assets that were disposed of or retired in 2018 and 2019 for the Tumbler Ridge Division that resulted in additions to the Plan Gains and Losses – deferral account. Extracts of the tables are included below.


Please comment on why the following assets were disposed of or retired prior to the end of their useful life with no salvage value:

Division and Year

Asset Estimated Useful Life

Acquisition Year

NBV December 31, 2019

FSJ 2019 Serv ice Line Disposals - 1996 Pool 50 1996 18,220.92 FSJ 2018 Service Line Disposals - 1996 Pool 50 1996 9,719.98 DC 2018 1220m 60.3mm St Pipe - Bessborough 60 1986 43,575.38 TR 2019 600m 114mm Y J Coaled Pipe - MP 8.15

Flatbed Creek 60 1975 20,259.08

Please comment on whether these asset categories are being under depreciated, and if the

estimated useful lives should be re-visited and/or revised.

H. SHARED SERVICES RECOVERY FROM PNG(NE)

Reference: SHARED SERVICES COST ALLOCATION TO PNG(NE) FSJ/DC DIVISION AND TR DIVISION PNG-West Division 2020-2021 RRA proceeding, Exhibit B-3, BCUC IR 10.1.1; PNG-West Division 2018-2019 RRA proceeding, Exhibit B-3, BCUC IR 46 Series, Attachment BCUC 1.46a, pp. 12, 24 Maximo Sustainment Costs

In response to the BCUC IR 46 series in the PNG-West 2018-2019 RRA proceeding, PNG provided Attachment BCUC 1.46a which included the PNG GIS Implementation Business Case, and on page 12 of the attachment it stated:

Experience with Maximo integration — PNG is undertaking an implementation of a Computerised Maintenance Management System (CMMS) based on the IBM Maximo software application. AUI has a mature implementation of Maximo and experience in developing and supporting its interface with its GIS. AUI can provide directly applicable and cost effective expertise in integrating GIS with Maximo.

Further in response to BCUC IR 10.1.1 in the PNG-West 2020-2021 RRA proceeding, PNG stated:

Computerized Maintenance Management Systems (CMMS): PNG is implementing the Maximo system to support the planning and scheduling of all associated preventative maintenance and capital work. Maximo provides comprehensive support of PNG assets, maintenance, resource, and parts supply chain management needs. The CMMS provides enterprise asset management software for long and short-term planning, preventive, reactive and condition-based maintenance, schedule management, resource optimization and key performance indicators.

Please clarify whether “CMMS” and “Maximo” are references the same PNG system. If not, please discuss the differences between the two systems.

In response to the BCUC IR 46 series in the PNG-West 2018-2019 RRA proceeding, and as stated above, PNG provided Attachment BCUC 1.46a. On page 24 of the attachment Figure 2 illustrates the Network Architecture Diagram, reproduced below.


Considering the recent system upgrades, please confirm, or explain otherwise, that the Maximo

system only interfaces with the GIS system.

79.2.1 If not confirmed, please list the other system(s) Maximo is connected to or interfaces with, and if not provided in the Amended Application, please describe the system(s).

Please update the above network architecture diagram to reflect the recent system upgrades and include any other systems the GIS project will connect to, or interface with.

Please provide a similar network architecture diagram for (1) the Asset Record Modernization (ARM) project, and (2) the hydraulic modeling software (i.e. Synergi Gas software).

Reference: SHARED SERVICES COST ALLOCATION TO PNG(NE) FSJ/DC DIVISION AND TR DIVISION Exhibit B-2 FSJ/DC, Section 2.6, pp. 47, 49; TR, Section 2.6, p. 47; Exhibit B-3, BCUC IR 18.1, 18.1.1 and 18.2; PNG-West 2020-2021 RRA proceeding, Exhibit B-2, Section 2.5.1, p. 53; Exhibit B-3 PNG-West, BCUC IR 21.2, 23.2 and 24.1 721 – Administration

On page 49 of the FSJ/DC Amended Application, regarding Test Year 2020 costs in Account 721 – Administration, PNG(NE) states:

Increased cost allocation of approximately $253,000 due to:

Overall cost pool increase of approximately $857,000 due to a number of factors, including: JDE sustainment costs; higher Vancouver office rent; costs associated with transitioning to Microsoft 365; costs related to the HRIS; and general inflationary costs increases on all costs in this cost pool over Decision 2019 amounts.

On page 47 of the TR Amended Application, increases in Account 721 for Test Year 2020 are noted by PNG(NE), and this increase is supported with a similar explanation.

In response to BCUC IR 24.1 in the PNG-West 2020-21 RRA proceeding, PNG stated:

The annual base rent (including operating cost recoveries) for PNG’s previous Vancouver office was $332,000, or $43 per square foot. The base rent for the new office space is $450,000, or $52 per square foot.


Please provide the rent cost allocated to each of the PNG(NE) Divisions (FSJ/DC and TR) for the Test Year 2020 and 2021.

On page 53 of the PNG-West Amended Application, PNG provides the following table showing the allocation of JDE system costs between the divisions:


Please see the table that follows which summarizes the operating costs recorded in BCUC Account 721 for the noted systems. There are no capital costs associated with the JDE system, the HRIS system or the Microsoft 365 transition for Test Year 2020 as they were incurred in 2019.

Please confirm, or explain otherwise, that the revised allocation of JDE system costs between

PNG-West and FSJ/DC for Test Year 2020 as provided in response to BCUC IR 18.1 are the final forecast allocated costs and that the forecast costs for Test Year 2021 continue to be consistent with Table 21 in the preamble.

Please reconcile the 2020 forecast operating costs allocated to FSJ/DC in response to BCUC IR 18.1 ($147,200) to the increased cost allocation attributable to FSJ/DC for account 721 (approximately $253,000). Please also reconcile the total operating costs in response to BCUC IR 18.1 ($496,000) to the overall cost pool increase for Account 721 (approximately $875,000).


As the new payroll system is a web-based platform, each entity has paid its own costs for the implementation of the system. PNG paid $72,000 in 2019 for implementation costs associated with Phase One. These costs were set up as a prepaid expense and are being amortized as an expense over an eight-year period. Additional costs of approximately $36,000 are expected to be paid in 2020 to implement Phase Two, and these costs will also be amortized over the remaining term of the licenses.


These costs, together with ongoing subscription costs for Test Years 2020 and 2021, are included in the Amended Application and allocated as follows:

On page 47 of the FSJ/DC Amended Application, regarding JDE ERP and HRIS sustainment costs respectively, PNG(NE) states:

PNG’s costs are forecast to be $384,000 in 2020 (10 months) and $496,000 for 2021 (full year).

On a consolidated basis for PNG and PNG(NE), these costs have been forecast at $58,000 for Test Year 2020, reflecting the cost of monthly and implementation charges, and $90,000 for Test Year 2021, reflecting the cost of monthly charges for a full year.

Please provide a table illustrating the total actual to date and forecast implementation costs, including prepaid implementation costs, for the JDE, HRIS systems and Microsoft 365 transition, by account (operating and capital) and all relevant years (i.e. 2019, 2020 and 2021) for each division.

Please provide a breakdown of the annual ongoing costs for the JDE, HRIS and Microsoft 365 transition by division between ongoing subscription costs, prepaid implementation costs amortized each year, and any other ongoing costs.

In response to BCUC IR 18.1.1 in Exhibit B-3, PNG(NE) stated:

The costs noted are all part of the PNG-West shared services 721 – Administration cost pool and are allocated on the following bases:

• JDE System – allocated based on composite average allocator

• HRIS System – allocated based on employee count allocator

• Microsoft 365 – allocated based on composite average allocator

Please explain why the composite average allocator was selected as the basis for allocating costs associated with the new JDE system and Microsoft 365 to the PNG divisions (West, FSJ/DC and TR).

80.6.1 Please discuss any alternatives PNG considered for allocating these costs amongst the divisions, (e.g. based on number of licenses), the pros and cons of each and why these alternatives were rejected.

In response to BCUC IR 18.2 in Exhibit B-3 regarding the Microsoft 365 transition, PNG(NE) stated: “At this time, PNG(NE) does not anticipate any annual cost savings associated with the new HRIS system.”

Please clarify whether the response to BCUC IR 18.2, as copied in the preamble, relates to Microsoft 365 rather than “the new HRIS system”.



There are no capital costs for the transition to the Microsoft 365 platform for the historic period nor Test Years 2020 and 2021. Operating costs associated with Microsoft 365 were approximately $7,000 for 2019 and estimated at approximately $85,000 for each of Test Years 2020 and 2021.

Please reconcile the expected operating costs associated with Microsoft 365 of approximately $85,000 for each of Test Years 2020 and 2021 to the forecast cost provided in IR 18.1.

I. RATE BASE

Reference: RATE BASE Exhibit B-2 FSJ/DC, Section 2.3, p. 30; AMR Meter Installations

On page 30 of the FSJ/DC Amended Application, PNG(NE) states:

PNG(NE) anticipates filing an application to the BCUC in early 2020 for a Certificate of Public Convenience and Necessity (CPCN) to update and replace the current manual meter reading process for residential and commercial customers with automated meter reading (AMR) infrastructure in the communities it serves, including FSJ, DC and TR.

On March 25, 2020, PNG(NE) filed the Application for PNG(NE) CPCN AMR to update and replace the current manual meter reading process for residential and commercial customers with AMR infrastructure in FSJ, DC and TR Divisions.

Please discuss the rationale for seeking approval to record the cost of service impact of the AMR Project as part of the current RRA, given that a CPCN was expected to be filed for the project in early 2020 (since filed on March 25, 2020) and a CPCN has not yet been granted.

81.1.1 Please discuss whether PNG(NE) considered excluding the cost of service impact of the AMR Project from the current RRA given the expected filing of the CPCN and the fact that a CPCN has not yet been granted. If yes, please discuss why PNG(NE) did not proceed with this approach. If not, please discuss why not.

81.1.2 Please discuss whether PNG(NE) considered including the cost of service impact of the AMR Project in a deferral account, with the disposition of the account to be determined following any BCUC decision regarding the CPCN. If yes, please discuss why PNG(NE) did not proceed with this approach. If not, please discuss why not.

Reference: RATE BASE Exhibit B-2 FSJ/DC, Section, p. 65; Exhibit B-3, BCUC IR 27.1, 27.2; Exhibit B-5, BCOAPO IR 1.2. New Services


PNG(NE) has forecast that it will be installing 80 new services each year for 2020 and 2021 for the Dawson Creek service area and has also forecast that it will be installing 90 new services each year for 2020 and 2021 in the Fort St John Service Area.

Please clarify whether the new forecast service refers to new service lines or new customers.


Please provide a table with the number of new services installed and new services expenditures for each of the Dawson Creek and Fort St John service areas from 2015 to 2019 (forecast and actual) and 2020 to 2021 (forecast).


The volatile nature of the economics in the oil and gas industry influences the development opportunities in northeastern British Columbia. The markets can turn upwards or downwards at any moment, depending upon the macroeconomics faced by Canada and the world. PNG(NE) submits that its utilization of the five-year average expenditure is considered appropriate, as it allows the company to level the impacts of any economic shift that is experienced by regional markets. A five-year timeframe has historically provided a reasonable timescale for gaining an accurate representation of the average for that market.

In response to BCOAPO IR 1.2, PNG(NE) stated that with respect to the impact of the COVID-19 pandemic and its Forecast Capital Expenditures “PNG(NE) has not revised its forecasted capital expenditures at this time and will be monitoring this closely in the coming weeks.”

With consideration to the impact of COVID-19 on PNG(NE) and its operations, please discuss whether the use of the five-year average expenditure for forecasting new services remains appropriate for the Test Period. If yes, please explain why. If not, please provide any revised forecasts, as applicable.

82.3.1 Please discuss whether PNG(NE) has considered revisions to any other capital expenditure forecast methodologies included in the Amended Application.

On page 65 of the FSJ/DC Amended Application, PNG(NE) states regarding New Services:

The test year forecast has been made in consideration of the five-year average (2015- 2019) expenditure for this type of work of $759,000 and anticipated activities for the period. [Emphasis added]

Please clarify the scope of the “anticipated activities” referenced in the preamble and their impact on the New Services forecast for both Test Years.

Reference: RATE BASE Exhibit B-3, BCUC IR 28.1, 28.4 Mobile/Heavy Equipment

In response to BCUC IR 28.1 in Exhibit B-3, PNG(NE) provided the following table showing decision and actual mobile/heavy equipment costs from 2015 to 2019, as well as forecasts for 2020 and 2021:

Please elaborate on the likelihood of all mobile & heavy equipment purchasing taking place in

2020 and 2021 given the significant increase relative to previous years.

Please discuss whether PNG shares mobile/heavy equipment between West and NE divisions. Please elaborate on the pros and cons of any type of vehicle sharing approach between PNG divisions.


In response to BCUC IR 28.4 in Exhibit B-3 requesting annual cost savings and incremental costs as a result of the primary contract closing down its operation, PNG(NE) stated:

Cost savings annually are significant. For example, a contractor working the 6-month construction season will invoice PNG(NE) approximately $12,000/month for use of a backhoe. PNG(NE) submits that a $72,000 annual charge for use of a backhoe is a great stimulus for procurement of its own equipment that can be used for core work and emergency response. As a further example, PNG(NE) notes that the contractor’s overtime rate was higher than PNG(NE)’s internal overtime labour rate, making it more reasonable for PNG(NE) to do as much of the work as practicable.

Please explain whether the cost savings have been factored into the Test Period for all divisions (PNG-West, PNG(NE) FSJ/DC and TR). If yes, please provide the account where the savings are realized.

Reference: RATE BASE Exhibit B-3, BCUC IR 29.1 29.3; PNG(NE) 2018-2019 RRA proceeding, Exhibit B-9, BCUC IR 80.3. Distribution Main Improvements – Mechanical Couplings


PNG(NE) can confirm that it has approximately 3,250 mechanical couplings, approximately 85% of the population, remaining to replace in Dawson Creek service area. In the Fort St John service area, PNG(NE) has approximately 1,500 mechanical coupling, approximately 35% of the population, remaining to replace.

Please confirm whether PNG(NE) has determined the location of the mechanical couplings that remain to be replaced in each of the Dawson Creek and Fort St John service areas.

84.1.1 Please discuss whether PNG(NE) has assessed the replacement priority ranking for the mechanical couplings that remain to be replaced in its service areas. Please elaborate how PNG(NE) selects the mechanical couplings which are to be replaced each year.

In response to BCUC IR 80.3 in the PNG(NE) 2018-2019 RRA proceeding BCUC IR 80.3, PNG(NE) stated:

Mechanical couplings were used to join pieces of steel pipe together instead of welded joints. They were originally installed without re-enforcement to prevent them from pulling apart. Couplings are not specifically mentioned in the latest Distribution Integrity Management Plan (DIMP) published December 18, 2017, but are included in the broader category of Natural Forces causing damage to facilities due to ground movement (frost, etc.) or falling debris (ice, snow, etc.). Frost action in some soils can cause movement of the ground with sufficient force and displacement to pull apart unreinforced couplings.

Please discuss any alternative approaches PNG(NE) considered to addressing the identified issues with mechanical couplings (e.g. reinforcing un-reinforced couplings, etc).

84.2.1 Please discuss whether any of the assessed alternatives met the objective of the mechanical coupling replacement program.

84.2.2 Please provide any cost analyses completed on the acceptable alternatives to the mechanical coupling replacement program.


In response to BCUC IR 29.3 in Exhibit B-3, PNG(NE) stated: “As identified, PNG(NE) has a replacement program for these mechanical couplings to mitigate these risks; this replacement program is similar in nature to other North American utilities to remove these aging and obsolete couplings.”

Please provide examples of other North American utilities undergoing or which have undergone similar mechanical coupling replacement programs.

Reference: RATE BASE Exhibit B-3, BCUC IR 36.1 Block Valve Installation


Due to the complexities associated with this program the number of valves replaced each year under approved and pursued budgets will depend on the specific valve(s) location and if any cost or resource related synergies can be realized with other programs like the Steel Mains replacement project.

Please elaborate on the cost or resource related synergies that may be realized between the Block Valve installation program and other programs like the Steel Mains replacement project.

85.1.1 Please clarify whether PNG(NE) anticipates any cost or resource related synergies between the projects during the current Test Years and whether any cost savings have been accounted for in the Amended Application.

Reference: RATE BASE PNG(NE) 2018-2019 RRA proceeding, Exhibit B-9, BCUC IR 91.1. Baldonnel Line Lowering

In response to BCUC IR 91.1 in the PNG(NE) 2018-2019 RRA proceeding, PNG(NE) stated:

A site visit in early 2016 noted the lagoon had grown, was in a state of near breach, had previously breached and was actively seeping on to the right of way. … PNG(NE) has reached out to the Ministry of Environment (MOE), which permits the lagoon and has caused the owner to make repairs but the problems continue.

As of late April 2018, PNG(NE) requested the MOE to cause the permit holder to cease discharging effluent in the lower 3rd of the coulee slope which significantly contributes to the already noted geotechnical issues. The BC OGC has also been kept abreast of this issue. As geotechnical conditions can and are being exacerbated by the lagoon’s seepage, continuous state of near failure, and the permitted activity (MOE) of discharging into the coulee, PNG(NE) has determined that the best course of action to ensure the integrity of the pipeline and the security of gas supply is to relocate the pipeline away from the ongoing threat from the lagoon discharge and the present geotechnical risk.

Please provide an update regarding any responses received from the Ministry of Environment (MOE) regarding this lagoon. Please also provide an update regarding any repair directives issued by the MOE to the lagoon owner and the outcome of any directed repairs.


Reference: RATE BASE Exhibit B-3, BCUC IR 34.1 Asset Records Modernization Project (ARM)

In response to BCUC IR 34.1 in Exhibit B-3, PNG(NE) provided the following table that breaks down the ARM costs allocated to each division.

Please provide the basis of allocating project costs to the divisions and explain whether actual costs are allocated differently from forecast costs.

Please explain whether there are any ongoing annual maintenance or sustainment costs that will be associated with the project and provide the annual costs by account number.

Reference: RATE BASE Exhibit B-3, BCUC IR 37.1; PNG-West Division 2018-2019 RRA proceeding, Exhibit B-6, BCUC IR 91.1 Information and Data Management Systems – Geographic Information System (GIS)

In response to BCUC IR 37.1 in Exhibit B-3, PNG(NE) provided the following table that breaks down the consolidated GIS costs allocated to each division.

In response to BCUC IR 91.1 in the PNG-West 2018-2019 RRA proceeding, PNG stated: “[t]hese costs will be allocated to each division based on the shared services cost allocation methodology.”

Please explain whether actual costs are allocated differently from forecast costs. If so, please discuss the methodology of allocating actual costs. If not, please clarify why the actual amount allocated does not equal the forecast allocation percentage in the table above.


Reference: RATE BASE Exhibit B-3, BCUC IR 44.5 Information and Data Management Systems – Synergi Gas Software

In response to BCUC IR 44.5 in Exhibit B-3, PNG(NE) provided breakdown of total hydraulic modelling system costs over the Test Period.

Further in the same response PNG(NE) stated: “All costs for the test period are of a capital nature given that activities are limited to the capitalization of implementation costs and exclude any operating expense related sustainment costs expected to be incurred in future test periods.”

Please discuss the timeline to complete this project. If the timeline extends beyond the Test Period, please expand the above table to breakdown the total hydraulic modelling system costs by year.

Please provide the annual sustainment costs associated with the hydraulic modelling system. Please breakdown the estimated costs by account.

J. CAPITAL STRUCTURE AND RETURN ON CAPITAL

Reference: CAPITAL STRUCTURE AND RETURN ON CAPITAL Exhibit B-3, BCUC IR 46.1, 46.4 Financing Costs

In response to BCUC IR 46.1 in Exhibit B-3, PNG(NE) provided an update to the forecast short-term and long-term interest rates and the resulting impact on the 2020 and 2021 cost of service for Fort St John, Dawson Creek and Tumbler Ridge. PNG(NE)’s statements for each region is provided below: Fort St John

The resulting impact on the 2020 and 2021 cost of service from the updated 90 day treasury bill rate on Fort St John’s 2020 and 2021 short term debt costs would result in a decrease in costs of $23,000 and $40,000, respectively.

The resulting impact on the 2020 and 2021 cost of service from the updated 90 day treasury bill rate on Fort St John’s 2020 and 2021 long term debt costs would result in a decrease in costs of $98,000 and $134,000, respectively.

Dawson Creek

The resulting impact on the 2020 and 2021 cost of service from the updated 90 day treasury bill rate on Dawson Creek’s 2020 and 2021 short term debt costs would result in a decrease in costs of $22,000 and $31,000, respectively.

The resulting impact on the 2020 and 2021 cost of service from the updated 90 day treasury bill rate on Dawson Creek’s 2020 and 2021 long term debt costs would result in a decrease in costs of $42,000 and $73,000, respectively.


Tumbler Ridge

The resulting impact on the 2020 and 2021 cost of service from the updated 90 day treasury bill rate on Tumbler Ridge’s 2020 and 2021 short term debt costs would result in a decrease in costs of $4,000 and $5,000, respectively.

The resulting impact on the 2020 and 2021 cost of service from the updated 90 day treasury bill rate on Tumbler Ridge’s 2020 and 2021 long term debt costs would result in a decrease in costs of $16,000 and $23,000, respectively.

Please discuss the 2020 and 2021 rate impact of using the revised 90 day treasury bill interest rate forecast.

K. CAPITAL EXPENDITURE REPORTING – ACTUAL VS DECISION

Reference: CAPITAL EXPENDITURE REPORTING – ACTUAL VS DECISION Exhibit B-3, BCUC IR 51.3; PNG(NE) 2018-2019 RRA proceeding, Exhibit B-9, BCUC IR 82.1 Cecil Lake Aluminum Replacement – FSJ

In response to BCUC IR 51.3 in Exhibit B-3, PNG(NE) provided the following table summarizing actual costs for project:

Further in response to BCUC IR 51.3 in Exhibit B-3, PNG(NE) stated:

Final project scope was to enact discrete pipeline and regulating station integrity improvements related to cathodic protection and code compliance from a materials and process design and operation perspective. These activities included, but were not limited to:

• Inspect, repair, and recoat underground (U/G) to aboveground (A/G) piping transitions and improve external coating protection

• Inspect, repair, and recoat U/G flange sets • Improve cathodic protection at the Cecil Lake Purchase station and along the

pipeline route to • Cecil Lake Station #3 • Enact operational, integrity and code compliance improvements at Cecil Lake

Station #3 o Line heater replacement including pilings and pipe rack o Removal of station yard high pressure to low pressure piping bypass

configuration o Removal of high risk A/G camelback riser and replace with U/G pipe

spool o Improve station access approach road Improve operational access

within pipe yard o Re-pipe station for compliance


Please provide a breakdown of actual 2018 and 2019 contractor costs for the activities included in the preamble and any other activities that are not included in the preamble.

In response to BCUC IR 82. 1 in the PNG(NE) 2018-2019 RRA proceeding BCUC IR 82.1, PNG(NE) stated:

In addition to the change in pipeline materials, the project scope is proposed to include an increase in pipeline diameter and modifications to existing pressure regulating stations as required in order to rectify an existing capacity constraint within the Cecil Lake area distribution system currently supplied by the aluminum pipeline.

Please discuss whether the project scope in addition to the change in pipeline material described in the preamble has been completed in 2018 and 2019. Please discuss any Cecil Lake System modifications or betterments which have not been completed and are still required.

91.2.1 If any modifications or betterments are outstanding, please provide the cost estimates to complete the work.

91.2.2 Please provide the rationale for treating the project expenditures as capital expenditures, with reference to the applicable US GAAP section(s) as it relates to the nature of expenditures.

L. COST OF SERVICE REPORTING – ACTUAL VS DECISION

Reference: COST OF SERVICE REPORTING – ACTUAL VS DECISION Exhibit B-2 FSJ/DC, Tab 1, p. 4; Exhibit B-3, BCUC IR 58.1 Account 875 – Mains and Service


PNG(NE) does not have a definitive conclusion to the reasoning for lower than anticipated repairs in 2019. One factor may be the enhanced focus given to contractor engagement for awareness of PNG(NE) assets in recent years. Another factor may be the reduction in economic growth experienced in the area resulting in less excavation works which gives less opportunity for line hits. There is also a potential that this year could be an outlier in the trends for underground leaks.

The following is a BCUC Staff extract from Tab 1, page 4 of the FSJ/DC Amended Application.

Considering the constant fluctuations of actual costs for Account 875, increasing/decreasing every second year, please explain why Test Year 2021 forecast costs are expected to remain consistent to 2020.

Reference: COST OF SERVICE REPORTING – ACTUAL VS DECISION Exhibit B-4, BCUC IR 13.1; Account 688 – Other General Operations


In 2020, PNG will be conducting an internal table-top exercise utilizing the Emergency Response Plan across the organization, including the PNG-West and the PNG(NE)


divisions and a full-scale exercise in 2021 utilizing external resources and agencies.

Please provide the forecast cost associated with the Emergency Response Plan for 2020 and 2021 by account and division (PNG-West, FSJ/DC and TR).

M. OTHER MATTER TO BE ADDRESSED FROM PRIOR YEAR DECISIONS

Reference: OTHER MATTER TO BE ADDRESSED FROM PRIOR YEAR DECISIONS Exhibit B-3, BCUC IR 62.3, 62.6, 62.8.1 and 62.8.2 Reporting on Significant Capital Projects

In response to BCUC IR 62.3 in Exhibit B-3, PNG provided the following table to show the proposed threshold as a percentage of actual capital expenditures.

Please recast the table above to illustrate the capital expenditures that would be captured

based on a $500,000 threshold as a percentage of total capital expenditures for each year between 2015 and 2019.

In response to BCUC IR 62.6 in Exhibit B-3, PNG stated it “…did not consider other project characteristics beyond a dollar threshold in determining which projects should be included in the proposed reporting.”

For each of the FSJ/DC and TR Divisions please provide the capital expenditure reporting threshold of $250,000, $500,000, and $750,000 as a percentage of total rate base, with supporting calculations.

Please discuss the pros and cons of using the following factors to determine the capital expenditure reporting threshold:

• Threshold as a percentage of total rate base; • Total annual project expenditures captured by the capital expenditure reporting threshold

as a percentage of total annual project expenditures; and • Number of projects per year captured by the threshold.

In response to BCUC IR 62.8.2 in Exhibit B-3, PNG stated:

As noted in the response to Question 62.8, PNG-West and PNG(NE) have made use of an informal minimum threshold of $1,000,000 as a general guideline in deciding on whether to file CPCNs or 44.2 applications. A cursory review of other utilities under the BCUC’s jurisdiction suggest that this threshold may be on the low side.


If a threshold were to be established, PNG(NE) suggests that a greater amount, say between $1,500,000 to $2,000,000, may be more appropriate as it would potentially reduce the regulatory burden on PNG(NE). Based on actual experience for 2017 to 2019, projects at the $1,500,000 to $2,000,000 expenditure level would represent 25.5% of total capital expenditures for FSJ/DC and 78.1% of total capital expenditures for TR during this period. As per the table provided in response to Question 62.5 with data for 2015 to 2019, this higher threshold would have required two CPCN applications during this time period, one for FSJ/DC (DC Gate #1 Station Replacement) and one for TR (TR Transmission Mainline Repair), the same as would be required at a $1,000,000 threshold.

If the CPCN threshold were to be established at $1,000,000 for the FSJ/DC and TR Divisions, please provide all project expenditures that would be filed as CPCNs as a percentage of total capital expenditures for 2017 to 2019 for each of FSJ/DC and TR.

For each division (FSJ/DC and TR) please provide the CPCN threshold that would be required to represent 20 to 30 percent of the total capital expenditures for 2017 to 2019.

Please provide the individual CPCN threshold of $750,000, $1,000,000, $1,500,000, $2,000,000 and $2,500,000 as a percentage of total rate base, with supporting calculations for each of the FSJ/DC and TR Divisions.

Please discuss the relevance of public interest components of a capital project in setting a CPCN threshold.

Please discuss the pros and cons of using the following factors in determining an appropriate CPCN threshold:

• The individual CPCN threshold as a percentage of total rate base;

• Total annual project expenditures captured by the CPCN threshold as a percentage of total annual project expenditures and;

• Number of projects per year captured by a CPCN threshold. In response to BCUC IR 62.8.1 in Exhibit B-3, PNG(NE) stated that the following factors would be relevant to setting a minimum threshold for CPCN or section 44.2 expenditure schedules:

• Materiality of expenditure

• Nature of expenditure (threshold may vary by type of expenditure)

• Timing of expenditure (potentially in between revenue requirements applications)

Please elaborate on the relevance of each factor, specifically the nature and timing of expenditures in relation to a minimum CPCN or section 44.2 expenditure schedule threshold.

94.9.1 Please address how the nature of an expenditure, specifically whether the expenditure is an extension to the existing system, is relevant, if at all, to the decision whether to file a CPCN or a section 44.2 expenditure schedule.

Reference: OTHER MATTER TO BE ADDRESSED FROM PRIOR YEAR DECISIONS Exhibit-2 FSJ/DC, Section 3.4.1.4, pp. 124-125; TR, Section 3.4.1.4, pp. 101-102 Automotive Cost Allocation

On page 124 of the FSJ/DC Amended Application and 101 of the TR Amended Application, PNG(NE) states the following with respect to the recommended approach for the capital allocation:


Based on the forgoing, PNG proposes the following for allocating Automotive costs to capital projects:

• Continue to apply the current budgetary convention for allocating forecast Automotive costs to capital, whereby the divisional percentage of capital labour costs of consolidated labour costs is applied to the consolidated Automotive cost pool; and

• Continue to apply the current administrative convention of allocating actual Automotive costs to capital, whereby a 15% factor is applied to capital labour costs and capitalized.

Please explain what the 15 percent factor used in the allocation of actual capital Automotive costs is based on.

Please comment on any alternatives that were that were considered with respect to the capital allocation, and why they were ultimately rejected.

Further on page 124 of the FSJ/DC Amended Application and page 101 of the TR Amended Application, PNG(NE) states the following with respect to the recommended approach for the operating cost allocation:

…PNG proposes the following:

• Once the consolidated Automotive cost pool has been established, subtract the costs identified as being attributable to capital in order to arrive at the operating cost pool.

• Apply the five-year rolling average of each division’s actual percentage distribution of operating Automotive costs to the test year operating cost pool.

Please comment on any alternatives that were considered with respect to the operating cost allocation, and why they were ultimately rejected.

On page 125 of the FSJ/DC Amended Application and 102 of the TR Amended Application, PNG(NE) presents the following table summarizing its historic and proposed methodology for forecasting the consolidated pool of Automotive costs:

Further on the same pages, PNG(NE) states:

PNG recommends that the consolidated Automotive cost pool for Test Year 2020 be forecast based on forecast 2019 actual costs with a 2% provision for inflation. PNG has reflected this recommendation in this Amended Application. Test Year 2021 costs have been forecast at the Test Year 2020 amount inflated by 2% for inflation.


Please explain what is meant by “forecast 2019 actual costs.”

Please confirm that PNG(NE) recommends that the consolidated Automotive cost pool for 2020 be forecast based on 2019 forecast costs adjusted for 2 percent inflation.

95.5.1 If not confirmed, please explain the recommended methodology.

95.5.2 If confirmed, please explain why PNG(NE) does not use 2019 actual costs, adjusted for inflation, as the basis to forecast the Automotive cost pool for Test Year 2020.

Please re-create the table for the consolidated cost pool (illustrated in the preamble above) and adjust the proposed methodology by using the 2015 actual, rather than forecast, as the base and applying the inflation factor to actual costs for subsequent years.

95.6.1 Please explain why 2015 was selected as the base year.

Please explain whether PNG(NE) considered creating a forecast Automotive cost for each division based on expected costs. Please comment on the pros and cons of this approach and why it was not selected.

Please discuss how using a 5-year rolling average of the actual consolidated cost pool impacts the forecast methodology.

Please explain how PNG(NE) plans to assess the effectiveness of the revised process for allocating operating and capital forecast costs and forecasting the consolidated Automotive cost pool. Please discuss the planned timing and frequency of the assessment(s).

Please comment on the strengths and weaknesses of using historic allocations of Automotive costs as a predictor of future allocations for the operating and consolidated forecast.

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